United States

California considers renewables mandate

Historically, the California energy market has been a policy trend setter, not least for wind, where the tax credits and standard offer contracts of the 1980s gave birth to wind farms. Today the market is clawing its way out of the disaster of its flawed deregulation, shunning market policies in favour of a regulated model. For wind this means adapting the Renewables Portfolio Standard from being an instrument for promotion of wind power in free

markets to a straightforward renewables mandate in a regulated regime

Hoping to salvage something from the wreckage of California's "competitive" electricity market that left wind developers high and dry, energy advocates are hot on the trail of a 20% Renewables Portfolio Standard (RPS) -- or some facsimile thereof. Without a renewables mandate that fosters long term power purchase contracts it has become abundantly clear that projects, even those awarded production incentives from the California Energy Commission (CEC), have a bleak future.

The state's Public Goods Charge (PGC) -- a levy on consumer utility bills won by renewables advocates in the 1996 deregulation bill -- is now widely viewed as insufficient to foster new development. Of the 1300 MW of new renewables projects awarded production incentives by the CEC since 1998, 76% of which are wind, only 200 MW, including 88 MW of wind, have come on-line.

In 2001, in the midst of the California electricity crisis, wind developers were largely excluded from the power contracts signed by the Department of Water Resources (DWR), the state agency thrust into the role of procuring power for the state's insolvent utilities. Only 2% of the 10,000 MW of contracts signed by the DWR over the next ten years is from renewable energy sources. This despite specific legislative encouragement of renewables in the bill that gave the DWR its mission and many hundreds of megawatts bid by renewable energy developers that were priced well below the $0.07-0.08/kWh average price of the signed fossil fuel contracts.

The DWR's renewables shut-out, combined with the virtual shut-down of the spot and retail markets and utilities with junk-grade credit ratings that are still hostile towards renewables, paints a bleak picture indeed for wind's future in the state.

The obvious injustice done to renewables during the entire deregulation debacle at least partly explains the public and political support for an RPS. Governor Gray Davis -- needing to put a happy face on the energy crisis before the November gubernatorial election and to make amends for his agency's stonewalling of renewables -- declared in March his support of Senate Bill 532 -- the RPS legislation sponsored by Democratic Senator Byron Sher. SB 532 "will continue [the] tradition of ensuring that renewables are a critical part of [California's] energy future," Davis declared.

Massive support

Leading the RPS effort has been the state's chief utility consumer advocacy group, TURN. It has provided a politically crucial complement to the usual renewable energy constituency, including the California Wind Energy Association (CalWEA), the Center for Energy Efficiency and Renewable Technologies (CEERT), and the Union of Concerned Scientists. The Energy Foundation, with substantial support from the Packard Foundation, is providing a million-dollar budget to support media, organising, and research for the campaign which has produced an impressive list of endorsers, including nearly 50 consumer, environmental, public health, labour and religious groups, dozens of state and federal elected officials, and the endorsements of the state's largest newspapers, The Los Angeles Times, San Francisco Chronicle, and San Jose Mercury News.

TURN's Matt Freedman explains the broad consumer support of the RPS: "Developing renewables as a hedge against the price volatility associated with fossil fuels and emissions permits will protect consumers from price spikes and provide long term rate stability." He notes that 94% of the 60,000 MW of new generation planned over the next six years throughout the western United States and Canada will run on natural gas.

Despite the support for the RPS, the job of passing the bill is far from over. RPS legislation was stalled in the last moments of the 2001 session when the legislation to which it was tied politically, the bail-out of Southern California Edison, failed. The RPS bill was then structured as a "classic" RPS -- a relatively simple requirement that all of the state's retail sellers of electricity meet a specified renewable energy goal, based on possession of tradable renewable energy credits, with a significant cents-per-kWh non-compliance penalty. Senator Sher had, however, pledged to exempt the municipal utilities due to the ability they clearly had to kill the bill in committee. Other opponents of the bill included all three investor owned utilities and the large industrial customers.

Total overhaul

A complete overhaul of the bill was being unveiled in May and is expected to get a committee hearing sometime this month. The new bill is the product of months of deliberation between SCE, TURN, CalWEA and CEERT after SCE pledged to support a "20%-by-2010" renewables mandate as long as it conforms to a regulated utility industry structure rather than the competitive market that the RPS was designed for (a reasonable request, given the collapse of the state's market). The coalition is betting that SCE's active support will be worth enough extra votes to get the policy adopted despite the bill being re-launched late in the legislative process.

The bill can now best be described as an "RPS-inspired" renewables mandate, since it includes a regulatory process for acquiring renewables and no longer explicitly includes tradable credits or cent-per-kWh penalties for renewable energy shortfalls, though both could be adopted by implementing agencies. The legislation has been structured to capture the central objective of the RPS: ensuring that competitively-procured renewable energy becomes a substantial part of the electricity resource portfolio on a defined timeline. As with many of the RPS variations which have seen the light in states across the US, achieving the goal is subject to reasonable cost limitations.

Defining need

Importantly, the renewable energy targets to be met by the three investor owned utilities are not conditioned on whether they currently forecast a need for additional energy or capacity. While the DWR contracts have ostensibly met much of the demand for new resources for the next several years, SCE and the RPS advocates argue that hinging renewables acquisitions on "need determinations" would be counter productive. Many unpredictable factors could create a need for renewables in the short term, including a western market that is still unstable, planned gas projects that may not materialise, possible outages or shutdowns of ageing facilities, dry hydro years, and the controversy surrounding the DWR contracts which could result in their renegotiation (some already have been renegotiated) or their nullification in court or by federal regulators. In the long term, capacity additions will almost certainly be necessary in any case.

The bill also provides for a market like acquisitions process by allowing each utility, overseen by the California Public Utility Commission (CPUC), to seek the least cost renewable energy resource that best fits its existing resource portfolio. Projects will be selected based on their total cost -- project cost plus transmission upgrade costs. The utility will identify transmission costs, subject to participant comment and CPUC review. Bidders will then be selected by the CPUC in consideration of least total cost, best fit with the assessment of resource need, and best fit with the annual renewables targets. It is likely that most or all bidders within entire resource areas will be selected at once to make cost effective the major transmission upgrades that will be necessary to effectively double California's existing renewable energy base.

Tackling transmission

An important shift in transmission policy is also included in the bill, one that is very valuable to the wind industry. The utilities are directed to lodge a request with the Federal Energy Regulatory Commission (FERC) allowing them to include transmission system upgrade costs in transmission tariffs -- when the costs result in system benefits -- rather than making generators pay for upgrades. Combined with the resource acquisition process, which is likely to grant contracts at once to many projects within a resource area, allocating costs to the transmission tariff rather than forcing the first projects developed within a new area to bear the brunt of transmission costs will greatly facilitate new developments. Though passing on transmission upgrade costs to consumers is allowed under current FERC rules, this method of cost allocation is not mandatory (though FERC is now considering a policy change in this direction). The change was initially by SCE, but quickly embraced by renewables advocates.

Flexibility is also provided. While tradable credits are not referenced in the bill, largely because the bill's opponents used them to distort the policy and confuse legislators, the bill permits compliance shortfalls and excesses to be averaged out over multiple years. This type of flexibility could be necessary due to the "lumpiness" of renewable resource additions: new and expanded transmission paths will open up resource areas following several years of infrastructure development. A resource acquisition process in which winning projects are selected for several years into the future will accommodate these physical realities.

Benchmark price

Legislators are assured that the total cost of the policy will be contained to reasonable levels through a combination of a "benchmark price" and the existing Public Goods Charge (PGC) fund. The benchmark price is the cost of the ten to 20 year contracts with renewables developers (not including associated transmission upgrade costs) that the utilities will be allowed to recover through their regulated retail rates. PGC funds will be used to pay bidders' costs that exceed the benchmark.

For example, if the benchmark price is $0.05/kWh for 15 years, a selected developer who bid $0.045 would receive a utility contract at that price and no PGC funds, while a selected developer who bid $0.055/kWh would receive a utility contract and PGC payments of $0.005/kWh. If the PGC fund is sufficient to cover as much renewable energy as is needed to meet the required annual targets, the targets will be met. If not, the amount of renewable energy that the utilities buy will be limited by the available PGC funds.

This process requires a significant change in the CEC's PGC funded program for new renewables projects: instead of auctioning off production subsidies, which would result in two bidding forums that invite inefficiency and gaming, the CEC will apply the PGC funds directly to the projects that win utility contracts.

Fixed price sources

The RPS coalition is betting that the available PGC fund -- at least $68 million annually through 2011 on top of unspent funds of a like quantity from the past four years, combined with a reasonable benchmark price, will allow the targets to be met. The CPUC must base the benchmark on the long term cost of new generating capacity. This must include fixed price sources of fuel for terms corresponding to the lengths of contracts to be offered plus the cost of any required environmental offsets, and must also reflect the indirect economic benefits that will result from the reduction in demand for natural gas.

The gas price reduction value is potentially significant. The US Department of Energy estimated in a 2001 report that the adoption of a national 20% RPS would reduce overall natural gas prices by up to 17%. Likewise, the estimated cost of a source of fuel whose price is fixed for up to 20 years (perhaps based on the cost of hedging instruments) should raise the benchmark price appreciably. Ideally, the benchmark would be established through a settlement process with one or more of the utilities (as SCE has indicated it would engage in) rather than through costly and time consuming CPUC hearings.

The Achilles heel of the entire policy, therefore, is that the benchmark could be set too low. This would cause a run on PGC funds, which would then be insufficient to reach the RPS targets. Even so, the policy should result in a substantial quantity of renewables.

The extent to which the bill remains intact as it winds its way through the legislative process this summer remains to be seen. Meanwhile, on its own initiative, the PUC is looking to adopt a renewables mandate under a "set-aside" law from the early 1990s that resulted in the ill-fated Biennial Resource Plan Update, which was cast aside as the new structure of the market was being debated. CalWEA and other RPS advocates are asking the PUC to adopt a policy along the lines of the legislation. While there is a good chance the PUC will act on its own initiative, a long term legislative mandate is clearly preferable.

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